Field of the Invention
The present invention relates to the development of underground reservoirs, such as hydrocarbon reservoirs comprising a fracture network and in particular, relates to a method for generating a mesh of the matrix medium and generating an image of the reservoir. The invention also relates to a method using the image to optimize management of the development through a prediction of the fluid flows likely to occur through the medium to simulate hydrocarbon production according to various production scenarios.
Description of the Prior Art
The petroleum industry, and more precisely reservoir exploration and development, notably of petroleum reservoirs, requires knowledge of the underground geology as precise as possible to efficiently provide evaluation of reserves, production modelling or development management. Indeed, determining the location of a production well, an injection well, the drilling mud composition, the completion characteristics, selecting a hydrocarbon recovery method (such as waterflooding for example) and the parameters required for implementing the method (such as injection pressure, production flow rate, etc.) requires good knowledge of the reservoir. Knowing the reservoir notably means knowing the petrophysical properties of the subsoil at any point in space and being able to predict the flows likely to occur therein.
The petroleum industry has therefore combined for a long time field (in-situ) measurements with experimental modelling (performed in the laboratory) and/or numerical modelling (using softwares). Petroleum reservoir modelling thus is a technical stage that is essential for any reservoir exploration or development procedure. The goal of such modelling is to provide a description of the reservoir.
Fractured reservoirs are an extreme type of heterogeneous reservoirs comprising two very different media, a matrix medium containing the major part of the oil in place and having a low permeability, and a fractured medium representing less than 1% of the oil in place and which is highly conductive. The fractured medium itself can be complex, with different sets of fractures characterized by their respective density, length, orientation, inclination and opening. The fractured medium is made up of all of the fractures. The matrix medium is made up of the rock around the fractured medium.
Those in charge of the development of fractured reservoirs need to know as precisely as possible the role of fractures. What is referred to as a “fracture” is a plane of discontinuity of very small thickness in relation to the extent thereof, representing a rupture plane of a rock of the reservoir. On the one hand, knowledge of the distribution and of the behavior of these fractures allows optimization of the location and the spacing between wells to be drilled through the oil-bearing reservoir. On the other hand, the geometry of the fracture network conditions the fluid displacement, on the reservoir scale as well as the local scale, where it determines elementary matrix blocks in which the oil is trapped. Knowing the distribution of the fractures is therefore also very helpful at a later stage to reservoir engineers who want to calibrate the models they construct to simulate the reservoirs, in order to reproduce or to predict the past or future production curves. Geoscientists therefore have three-dimensional images of reservoirs allowing location of a large number of fractures.
Thus, in order to reproduce or to predict (i.e. “simulate”) the production of hydrocarbons when starting production of a reservoir according to a given production scenario (characterized by the position of the wells, the recovery method, etc.), reservoir engineers use a computing software, referred to as reservoir simulator (or flow simulator), that calculates the flows and the evolution of the pressures within the reservoir represented by the reservoir model (image of the reservoir). The results of these computations enable prediction and optimization of the reservoir in terms of flow rate and/or of amount of hydrocarbons recovered. Calculation of the reservoir behavior according to a given production scenario constitutes a “reservoir simulation”.
A mesh of the matrix medium (rock) and a mesh of the fractured medium have to be generated in order to carry out simulations of flows around a well or on the scale of some reservoir cells (˜km2), by taking into account a geologically representative discrete network of fractures. It has to be suited to the geometric (three-dimensional diffuse faults and fractures location) and dynamic heterogeneities since the fractured medium is often much more fluid conducting than the matrix medium. These simulation zones, when fractured, can comprise up to one million fractures whose size ranges from one to several hundred meters, with very variable geometries of dip, azimuth and shape.
This stage is very useful for hydrodynamic calibration of the fracture models. Indeed, the discontinuity of the hydraulic properties (dominant permeability in the fractures and storage capacity in the matrix) often leads to use the double medium approach (homogenized properties) on reservoir models (hectometric cell). These models are based on the assumption that the representative elementary volume (REV) is reached in the cell and that the medium fracturation is high enough to allow homogenization methods to be applied (stochastic fracturation periodicity for example).
Within the context of petroleum reservoir development, discrete flow simulation methods are used, notably for permeability scaling (scale of a reservoir cell) and for dynamic tests (a small zone of interest (ZOI) in relation to the size of the reservoir). The computation times appear to be essential since computation is often carried out sequentially and a large number of times in optimization loops. It is well known that, in the case of dense fracturation (highly connected fractures), analytical methods are applicable whereas, in case of low connectivity indices, numerical simulation on a discrete fracture network (DFN) is necessary.
The numerical model of the matrix of the transmissivities relative to the various objects (diffuse faults, matrix medium cells), has to meet a certain number of double-medium criteria:
be applicable to a large number of fractures (several thousand fractures);
restitute the connectivity of the fracture network;
be evolutionary to account for all the fracture models (several fracturation scales, 3D disordered fractures, sealed faults, time-dependent dynamic properties, etc.);
the shape of the fractures (any plane convex polygon or ellipse) and the intersection heterogeneities between the 3D fractures have to be taken into account upon plane meshing of each fracture;
model the evolution of the pressure field in the “matrix” medium (less conductive and containing more fluid) as a function of the pressure field in the fractures by use of transmissivity terms (matrix/fracture exchange);
the number of simulation nodes, that is the number of pressure unknowns, has to be restricted to be able to use a numerical solver (what is referred to as a node is a volume element of the fracture or matrix medium of unknown pressure value); and
be fast and memory efficient (usable on a usual set and not only on a supercomputer).
With such needs, conventional meshes (finite element or finite volume) and the methods derived therefrom for local transmissivity construction are not applicable due to too large a number of nodes required for simulation.
The technique implemented in the FracaFlow™ software (IFP Energies nouvelles, France), which allows these limits to be exceeded using a physical approach based on analytical solutions of plane flow problems, is also known. The fractures are assumed to be constrained by geological beds (they entirely traverse them) and sub-vertical. A fracture is referred to as a constrained bed if it stops on geological bed changes. According to these hypotheses, all the intersections occur on any intermediate plane parallel to the geological layers. In the median plane of each geological bed, the nodes are on the intersections (a point) of the fractures on the plane (a matrix node and a fracture node in the same place). The vertical connections are carried by the fractures traversing several layers and the volumes associated with the nodes are calculated as all of the points (in the 2D plane, propagated vertically to the thickness of the layer) that are the closest to the node (in the medium considered).
This method reaches its limit when the fractures are not bed constrained and/or the dip of the fractures is not vertical. The intersections are in fact no longer present in each intermediate plane and the vertical connectivity can no longer be met. By increasing the number of intermediate planes, the error can be reduced (without ever being exact in the case of sub-horizontal fractures), but the number of nodes increases considerably and exceeds the limits imposed by the solvers.